Fluid streams derived from natural gas reservoirs, petroleum or coal, often contain a significant amount of acid gases, for example carbon dioxide (CO2), hydrogen sulfide (H2S), sulfur dioxide (SO2), carbon disulfide (CS2), hydrogen cyanide (HCN), carbonyl sulfide (COS), or mercaptans as impurities. These fluid streams may be gas, liquid, or mixtures thereof, for example gases such as natural gas, refinery gas, hydrocarbon gases from shale pyrolysis, synthesis gas, and the like or liquids such as liquefied petroleum gas (LPG) and natural gas liquids (NGL).
Various compositions and processes for removal of acid gases are known and described in the literature. It is well-known to treat gaseous mixtures with aqueous amine solutions to remove these acidic gases. Typically, the aqueous amine solution contact the gaseous mixture comprising the acidic gases counter currently at low temperature and high pressure in an absorber tower. The aqueous amine solution commonly contains an alkanolamine such as triethanolamine (TEA), methyldiethanolamine (MDEA), diethanolamine (DEA), monothenaolamine (MEA), diisopropanolamine (DIPA), or 2-(2-aminoethoxy) ethanol (sometimes referred to as diglycolamine or DGA).
In some cases, an accelerator, is used in combination with the alkanolamines, for example piperazine and MDEA as disclosed in U.S. Pat. Nos. 4,336,233; 4,997,630; and 6,337,059, all of which are incorporated by reference herein in their entirety. Alternately, EP 0134948 discloses mixing an acid with select alkaline materials such as MDEA, to provide enhanced acid gas removal. EP 0134948 teaches that only a select class of alkaline materials mixed with an acid is useable in aqueous alkaline solutions to provide increased acid gas removal.
Tertiary amines, such as 3-dimethylaminopropane-1,2-diol (DMAPD), have been shown to be effective at removing CO2 from gaseous mixtures, see U.S. Pat. No. 5,736,115. Further, in specific processes, e.g., the Girbotol Process, tertiary amines have been shown effective in removal of H2S, but show decreased capacity at elevated temperatures, for examples see “Organic Amines-Girbotol Process”, Bottoms, R.R., The Science of Petroleum, volume 3, Oxford University Press, 1938, pp 1810-1815.
Particularly important is the removal of sulfur based contaminants including hydrogen sulfide from fluid streams from oil and gas well due to the highly noxious nature of these gases. Certain attempts at selective removal of sulfur based compounds have been made.
Tertiary alkanolamines such as MDEA are inherently selective for hydrogen sulfide over CO2. Because of increasingly more stringent specifications towards hydrogen sulfide and sulfur dioxide emissions, there is a need for aqueous amine formulations capable of removing hydrogen sulfide selectively over CO2 along with treating the gas to a very low level of H2S (i.e. 10 ppmv).
EP 01,134,948 discloses the use of low pKa acid additives (lower than 7) to enhance the selective removal of hydrogen sulfide. The technology aims at altering vapor liquid equilibrium characteristics of the alkanolamine solvent in order to achieve lower amount of hydrogen sulfide in the treated gas. U.S. Pat. No. 4,892,674 discloses the use of severely hindered alkanolamine salts as an additive for an MDEA gas treating solvent in order to enhance the selective removal of hydrogen sulfide over CO2 compared to MDEA alone. This technology is a combination of the use of severely sterically hindered amine and low pKa acid additives to MDEA based solvents. US 2010/0288125 discloses the use of phosphonic acid additives in order to enhance hydrogen sulfide selective removal.
U.S. Pat. No. 4,085,192 discloses a process for removal of hydrogen sulfide using an aqueous mixtures of alkanolamine and sulfolane. The preferred amines are diisopropanolamine and methyldiethanolamine. This invention suffers from the limited acid gas carrying capacity of DIPA and MDEA based hybrid formulations.
U.S. Pat. No. 4,405,585 discloses a process and formulation for selective hydrogen sulfide removal using aqueous blends of sterically hindered amines and physical solvent (preferred solvent is sulfolane). This process includes a physical solvent having a high dielectric constant.
U.S. Pat. No. 5,705,090 discloses hybrid formulations for selective hydrogen sulfide removal using aqueous blends of polyethylene glycols and methyldiethanolamine. MDEA based hybrid formulations display low acid gas carrying capacity.
The Amisol process (Kohl & Nielsen, p 1231) uses aqueous blends of methanol and alkanolamines for selective hydrogen sulfide removal. The amines include diisopropylamine and diethylamine which both display low vapor pressure as well as diethanolamine (DEA) which display rather low basicity and is not selective for H2S over CO2.
WO 86/05474 discloses hybrid solvents for selective hydrogen sulfide removal. Amines include tertiary amines and sterically hindered amines. Physical solvents include glycols, glycol esters, glycol ethers, and N-methylpyrrolidone. These solutions are anhydrous (<5 wt % water).
While the above compounds are effective, they each have limitations which detract from their use in total organic sulfur removal. Therefore, there is a need for formulations allowing for the removal of total organic sulfur compounds.